The present invention relates to systems, compositions, and methods involved in the extraction of petroleum, natural gas, coal seam gas, and other substances from wells. In particular, the invention relates to additives used in hydraulic fracturing for the extraction of substances, primarily hydrocarbons, from an underground rock layer. In a particularly preferred embodiment, the invention relates to additive compositions at least partially coated with a water impervious coating, such as a polymer, and agents useful for preventing or reducing clumping of additive particles coated with such polymers.
Hydraulic fracturing, or “fracking” refers to the induction of fractures in underground rock layers by pumping a pressurized fluid within the well in order to cause fracturing of the rock layer in which the substances to be extracted are located. Although also useful for the extraction of other substances, hydraulic fracturing is of particular importance in the extraction of petroleum and natural gas for energy uses. This technology permits the extraction of substantial amounts of hydrocarbons from previously exploited oil and gas wells, thereby enhancing the yield of hydrocarbons from such wells, many of which were formerly considered to have been exhausted.
The vast natural gas reservoirs worldwide, particularly in North America, combined with the efficiency of hydraulic fracturing techniques, has led many experts to consider that natural gas will account for over 25% of world energy demand by 2035. Fracking techniques permit the extraction of large amounts of formerly inaccessible hydrocarbons. The United States, which has a technological and legal advantage over much of the world, is predicted to become the world's largest oil producer within the next 15 to 20 years due to large-scale use of hydraulic fracturing techniques.
Hydraulic fracturing comprises pumping large volumes of water, slurried with sand and/or another rigid agent or “proppant”, into a wellbore under high pressure. The water and proppant are combined in a “hydraulic fracturing fluid” or “fracking fluid” which may contain one or more additional chemical additive; such additive(s) may be chosen from a list of specific agent or classes of agents having various purposes, dependent on the petroleum formation into which they are introduced. The subterranean formations in which the hydraulic fracturing fluid is pumped our natural reservoirs typically porous sandstones, limestones, dolomite rocks or shale rock or coal beds. Hydraulic fracturing permits gas and oil to be extracted from rock formations existing at depths from, for example, about 5000 to about 20,000 feet or more. At these depths the porosity of the rock or pressure under which the reservoir is subjected may not be great enough to permit a natural flow of gas and oil from the rock at rates high enough to make its extraction economical. The introduction of fractures in the rock can increase the flow of oil and gas and the overall production of oil and gas from the reservoir rock.
Fractures are created by pumping the fracturing fluid into the well bore at a rate sufficient to increase the pressure within the well to exceed that of the fracture gradient of the rock. When the rock cracks, the proppant within the fracturing fluid keeps the crack open, and extends the crack still farther. The chemical additives are generally chosen for each well and geological formation to optimize the extraction of the gas or oil. For example, acid can be added to scour the perforations made in the rock; a gelling agent such as guar gum helps keep the sand or other granular agent (called a “proppant”) in suspension. Later in the process, viscosity reducing agents such as oxidizers and/or enzyme breakers are sometimes added to encourage the flow of hydrocarbons from the fracture site, or to break up the gelling agents and permit the induction of flow.
A typical aqueous hydraulic fracturing fluid comprises about 99.5% to about 90% (by weight) water and proppant, with the remainder of the mass (from about 10% to about 0.5% by weight) being chemicals. Various additives may be in liquid or solid form; additionally, the chemicals and additives disclosed below are examples of chemical agents that may perform the indicated function, and are not intended as an exhaustive list. Those of ordinary skill in the art are well aware of additional or alternative agents to those listed to serve these functions. Moreover, each and every of the indicated functions below may not be required to be used in each, or even any, specific instance.
Proppant:
Used to assist in causing and extending fractures, and maintaining fractures open once formed. Examples of proppants include, but are not limited to, nut shells, plastic beads, glass beads, sand, sintered alumina, urea prills and aluminum spacers.
Acid:
An acid helps dissolve minerals and initiate the fissure in the rock; such acids may comprise, for example, HCl at a concentration of about 0.12% by weight.
Biocide:
A biocide is often added to prevent the growth of bacteria in the water, and thus fouling in the pipe. Various biocides may be used, and their concentration depends upon the specific biocide used; for example, glutaraldehyde may be used as a biocide at a concentration of about 0.001% by weight.
Sodium Chloride:
Sodium chloride permits a delayed breakdown of gel polymer chains, and may be included at a concentration of about 0.1% by weight.
Corrosion Inhibitor:
A corrosion inhibitor may be used to prevent corrosion of the pipe; the coated APS particles of the present invention may provide corrosion inhibiting activity; additional corrosion inhibitors may also be provided, such as N,N-dimethyl formamide at a concentration of about 0.002% by weight.
“Breaker” Chemicals:
“Breakers” are oxidizing agents, enzymes, and/or other chemical agents that facilitate the process of degrading the viscosity enhancing agents of the fracking fluid and thereby decrease the fluid's viscosity when flowback of the gas or oil from fractured rock is desired. Breaker chemicals may include, for example, ammonium persulfate, sodium persulfate, potassium persulfate, sodium chlorite, ammonium bifluoride, ammonium fluoride, sodium fluoride, potassium fluoride, sulfamic acid, citric acid, oxalic acid, ammonium sulfate, sodium acetate and enzymes and mixtures of any two or more of these.
Borate:
Borate salts, which may be used at a concentration of about 0.007% by weight, maintains fluid viscosity as the temperature of the aqueous hydraulic fluid increases partially by promoting the formation of crosslinking between the chains or fibers of gelling agents. This is desirable in order to maintain the solid components of the hydraulic fluid in suspension as the fluid flows into the rock formation.
Lubricants:
Lubricants such as polyacrylamide and petroleum distillates may prevent or minimize friction between fluid and pipe; either or both of these agents may be present at, for example, a combined concentration of about 0.09% by weight.
Gelling Agents:
Gelling agents also help maintain the sand and chemical particles of the present invention in suspension within the fracking fluid. Such agents may include, without limitation, guar gum, hydroxypropyl guar (HPG), carboxymethyl, hydroxypropyl guar (CMHPG), and/or xanthan, and/or hydroxyethyl cellulose, which increase the viscosity of the water phase to help suspend the sand and particles.
Citric Acid:
Citric acid may be present, for example at a concentration of about 0.004% by weight, are to help prevent precipitation of metal oxides from solution.
Potassium Chloride:
Potassium chloride may be present at a concentration of about 0.6% by weight creates a brine carrier fluid.
Carbonates:
Sodium and/or potassium carbonate, which also may be present, maintain the effectiveness of cross linkers.
Alkyl Glycols:
Ethylene glycol and/or polyethylene glycols may also be added to prevent the deposition or formation of scale in the pipe. Solid scale inhibitor forms may alternatively or additionally be present.
Viscosity Enhancing Agent:
Isopropyl, for example, at a concentration of about 0.085% by weight may be added as a thickening agent.
As mentioned above, those of skill in the art are aware that this is a single example of one “typical” hydraulic fracturing fluid, and many variations, additions, and omissions can and should be made to such hydraulic fluids while maintaining the same essential properties to tailor the fluid to the particular oil or gas well conditions to be encountered.
Fracking operations may employ as much as 1,000,000 to 3,000,000 gallons of water or more. The water is generally transported to the site of operations in water trucks. A high-pressure pump, such as a pumper truck, injects the slurry of proppant, chemicals (which may include chemicals in particulate form) and water into the well, as far as 20,000 feet below the surface. The pressurized fluid mixture causes the rock layer to crack. The fissures are maintained open by the sand and/or other proppant so that oil and/or natural gas can flow out of the fissures through the well casing, and be collected from the top of the well.
Depending upon the requirements of the specific fracking operation, and the purpose(s) and class of chemical used, it may be desirable or useful for the chemical to be provided in a delayed or controlled release particle. For example, if the chemical is particularly active, it may exert its activity with greater potency than is required or needed at the well site. For example, the viscosity of the hydraulic fracturing fluid may be very quickly reduced, thereby failing to properly maintain the proppant in suspension. Furthermore, if the chemical agent is a reagent (rather than a catalyst) then the bulk of the chemical may be reacted early in the hydraulic fracturing process, and may not fully penetrate within the well fractures, particularly at depths where the chemicals activity may be particularly desired or required.
To overcome this problem various means can be used to deliver the active chemical to a depth, or proximal to a specific geological structure as desired. For example, a chemical having a particular activity may be substituted with another chemical having similar activity, but with a reduced reactivity or rate of reaction as compared to the first chemical. Additionally, or alternatively, the chemical may be formulated to be comprised in a particle or pellet that is suspended in the fracking fluid. The particulate nature of the fracking additive means that there will be a reduced amount of affidavit in contact with the fracking fluid directly as compared to, for example, a powdered or liquid additive. If the additive is slowly soluble in water, the inside of the particle will become exposed to the fracturing fluid when the outside of the particle has dissolved. This means that the particle will have traveled farther within the wellbore or fracture when it is solubilised or dispersed and the chemical will thus maintain its activity further within the well.
In other embodiments, the additive may be either largely soluble, or soluble in aggregates which disperse from the particle quickly and immediately exert their activity. For example, breaker additives start to degrade the viscosity enhancer in the fracturing fluid upon contact thereby lowering the efficiency of the fracturing process. In such cases, additional time and labor are needed to effect the reduction of the viscosity of fracturing fluids introduced into the subterranean formation. The use of organic breakers such as alkyl formate may alleviate this problem, since they can be applied along with the fracturing fluid. But these types of breakers rely on certain subterranean conditions, such as elevated temperature and time, to effect a viscosity reduction of the fracturing fluid. Since these organic breaker chemicals work on chemical change, such as hydrolysis, they are slow in effecting viscosity reduction. Furthermore, their performance can be unpredictable.
Water-soluble particulate solid chemicals at least partially encapsulated with coatings of water impermeable polymers and the like have been utilized heretofore. The encapsulating coatings on the water-soluble chemicals have been utilized to control the times when the chemicals are released in aqueous fluids. For example, encapsulated particulate solid chemicals have been used in oil and gas well treating fluids such as hydraulic cement slurries, formation fracturing fluids, formation acidizing fluids and the like.
Thus, coated particles have been proposed or used to delay or control the rate of release of fracking fluid additives, including breakers. For example, U.S. Pat. No. 5,102,558 to McDougall et al. discusses coating breaker chemicals (themselves coated onto a seed “substrate” such as urea) with a neutralized sulfonated elastomeric polymer. These polymers seal the water soluble breaker from the fracking fluid; the coating is slowly permeable to water and essentially impermeable to the breaker chemicals under well-bore conditions. Upon introduction into aqueous fracturing fluids or other aqueous wellbore fluids, the encapsulated particle slowly absorbs water by diffusion through the polymeric coating. This water dissolves the breaker substrate and sets up an osmotic gradient that in turn draws in more water. Pressure builds up inside the particle, and it expands until resealable micropores form in its walls. Concentrated substrate solution is then ejected through the micropores into the surrounding medium. This relives the pressure inside the capsule that then shrinks. The micropores reseal, and the process repeats itself until insufficient substrate remains for sufficient osmotic pressure to cause the particles to swell and micropores to form.
Norman et al., U.S. Pat. No. 5,373,901 disclose methods of making encapsulated chemicals for use in controlled time-release applications in hydraulic fracturing operations. In these methods, a coating comprising a partially hydrolyzed acrylic crosslinked to an aziridine or carbodiimide plus particulate silica, is applied to the particulate solid chemical. The hydrophobic acrylic co-polymer is present in this coating in an amount such that it provides a water-impervious dry shield on the encapsulated chemical; the silica particles introduce imperfections in the coating that permit a slowed leeching of the additive in water; preferably the coating provides a short delay in the release of the encapsulated chemical in the presence of water.
Reddy et al., U.S. Pat. No. 6,444,316 disclose methods of making encapsulated chemicals for use in controlled time-release applications. In these methods, a first coating is substantially similar to the coating of the '901 patent. A second, outer coating comprising a porous cross-linked hydrophilic polymer is next formed on the first coating. The porous hydrophilic polymer is present in the second coating in an amount such that when contacted with water it prevents the substantial dissolution of the encapsulated chemical for a selected time period.
Particles such as those disclosed in the '901 and '316 patents above depend upon “the presence of silica in the [outer] coating composition [which aids] . . . in introducing imperfections in the dry coating to facilitate the controlled release of the encapsulated chemical.” See e.g., '316 patent. In this system the size of the holes or imperfections created by the silica in the dry layer may be highly variable, and thus the controlled release itself of chemicals from the particle may be variable and depend not only on chemical factors, but on the presence, absence, or amount of mechanical shear forces on the particles due to collapse or closure of fractured rock formations.
International patent application Ser. No. 13/770,531, Little and Sundaram discloses particulate coated additive compositions for use in hydraulic fracturing operations, comprising a coating comprising a polymer and a wax component, wherein the coating may be formulated to be substantially water-impervious at low temperatures, and to release the additive when the formation temperature is above a given temperature or temperature range.
In the case of polymer-coated additive particles, the coating is usually applied in a fluidized bed or other similar spraying apparatus designed to evenly apply the coating while keeping the particles separate. However, while the coated particles are heat- and air-dried, they still tend to clump when they are placed onto packaging or containers. In extreme examples, the particles can form a hard “block” of aggregated particles that cannot be poured or otherwise easily handled for use.
Commercially available anti-adherent agents are used in the drug and food industries, for example, in the manufacture of medical capsules, tablets, and powders to prevent sticking. For example, magnesium stearate, is one of the most commonly used and generally effective such agents. It is used in myriad ways to prevent sticking; for example, magnesium stearate is used as a lubricating agent to prevent ingredients from sticking to manufacturing equipment during the compression of medical powders into tablets.
Other excipients used in the drug and food industries include vegetable and mineral oils, polyethylene glycol, sodium docecyl sulphate, glycerol palmitostearate, sodium stearyl fumarate, talc, and fumed silicone dioxide, and some of these are used as flow agents for foods such as sugar, salt and the like.
Each and every patent, patent publication, and other publication cited in this patent application is hereby expressly and individually incorporated by reference as part of this specification herein in its entirety.